The invention generally relates to communicating commands to a well tool.
Referring to FIG. 1, for purposes of measuring characteristics (e.g., formation pressure) of a subterranean formation 31, a tubular string 10 may be inserted into a wellbore which extends into the formation 31. In order to test a particular region, or zone 33, of the formation 31, the string 10 may include a perforating gun 30 that is used to penetrate a well casing 12 and form fractures 29 in the formation 31. To seal off the zone 33 from the surface of the well, the string 10 typically includes a packer 26 that forms a seal between the exterior of the string 10 and the internal surface of the well casing 12. Below the packer 26, a recorder 11 of the string 10 takes measurements of the formation 31.
The tool 21 typically has valves to control the flow of fluid into and out of a central passageway of the string 10. An in-line ball valve 22 is used to control the flow of well fluid from the formation 31 up through the central passageway of the test string 10. Above the packer 26, a circulation valve 20 is used to control fluid communication between an annulus 16 surrounding the string 10 and the central passageway of the string 10.
The ball valve 22 and the circulation valve 20 can be controlled by commands (e.g., xe2x80x9copen valvexe2x80x9d or xe2x80x9cclose valvexe2x80x9d) that are sent downhole. Each command is encoded into a predetermnined signature of pressure pulses 34 (FIG. 2) transmitted downhole to the tool 21 via hydrostatic fluid present in the annulus 16. A sensor 25 of the tool 21 receives the pressure pulses 34, and the command is extracted. Electronics and hydraulics of the string 10 then operate the valves 20 and 22 to execute the command.
For purposes of generating the pressure pulses 34, a port 18 in the casing 12 extends to a manually operated pump (not shown). The pump is selectively turned on and off by an operator to encode the command into the pressure pulses 34. A duration T0 (e.g., 1 min.) of the pulse 34, a pressure P0 (e.g., 250 p.s.i.) of the pulse 34, and the number of pulses 34 in succession form the signature that uniquely identifies the command.
FIG. 1 depicts a land-based well. However, similar pressure pulses may be used to communicate commands to a well tool that is disposed in a subsea well. For example, a subsea well may have a Blowout Preventor (BOP) that is located just above surface of the sea floor and is connected, at its lower end to a wellhead of the well and to the surface vessel by a pressure containing conduit known as a marine riser. The BOP stack forms a sealed entry point to the well as well as other devices, such as a tubing hanger (for example), a mechanism that, as its name implies, holds the top end of production tubing that extends down into the well bore. For purposes of installing the tubing hanger inside the well, a tool called a tubing hanger running tool (THRT) may be used, and this tool may be actuated via pressure pulses.
More specifically, the tubing hanger running tool may be tethered to a floating platform at the surface of the well. In this manner, a tubing called a landing string may be connected between the surface floating vessel/rig/platform and the THRT within a marine riser, onto which an umbilical containing hydraulic and electrical conduits may be clamped externally for the purpose of communication with the THRT. The long umbilical that is used to communicate commands to the tubing hanger running tool may be significantly expensive and may significantly increase the time needed to deploy and retrieve the tool.
Thus, there is a continuing need for an arrangement that addresses one or more of the problems that are stated above.
In an embodiment of the invention, a system for use with a subsea well that includes a BOP includes a fluid line and a tool that is not connected to the fluid line. The fluid line is connected to the BOP to communicate a pressure encoding a command, and the tool is adapted to decode and respond to the command when the tool is inside the BOP.